drilling engineering and operations (2)

5/24/2018 Drilling Engineering and Operations (2)

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Note: The source of the technical material in this volume is the Professional

Engineering Development Program (PEDP) of Engineering Services.Warning: The material contained in this document was developed for Saudi

Aramco and is intended for the exclusive use of Saudi Aramcos employees.Any material contained in this document which is not already in the publicdomain may not be copied, reproduced, sold, given, or disclosed to thirdparties, or otherwise used in whole, or in part, without the written permissionof the Vice President, Engineering Services, Saudi Aramco.

Chapter : General Engineering For additional information on this subject, contactFile Reference: AGE-106.05 PEDD Coordinator on 874-6556

Engineering Encyclopedia

Saudi Aramco DeskTop Standards

DRILLING ENGINEERING AND OPERATIONS


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Engineering Encyclopedia Introduction to Exploration, Drillling and Petroleum Engineering

Drilling Engineering and Operations

Saudi Aramco DeskTop Standards i

Section Page

INFORMATION............................................................................................................... 3HISTORY OF DRILLING................................................................................................. 3CONVENTIONAL ROTARY DRILLING........................................................................... 9

Drilling Rig Operations.......................................................................................... 9Drilling Rig Subsystems...................................................................................... 15

The Drillstring (Rotating System)............................................................. 15The Fluid System (Circulating System).................................................... 36

The BOP System (Blowout Prevention System)................................................. 45The Hoisting System................................................................................ 51The Power System .................................................................................. 53

Measurement While Drilling................................................................................ 54Directional Drilling............................................................................................... 56

BOTTOMHOLE ASSEMBLY DRILLING ....................................................................... 59Principles............................................................................................................ 60

Applications ........................................................................................................ 62ENGINEERING APPLICATIONS .................................................................................. 63

Maximum Tension Load in the Drillstring............................................................ 63Killing the Well.................................................................................................... 63

Drilling Hydraulics............................................................................................... 66The Steady-State Incompressible Flow Equation (The Energy Equation) .......... 69

SAUDI ARAMCO OFFSHORE DRILLING RIGS........................................................... 75Jack-Up Drilling Rig (For Drilling the Wells)........................................................ 75Cantilever ........................................................................................................... 76Slot ..................................................................................................................... 77Steel Jacket Structures (As the Production or Wellhead Platforms)................... 78

GLOSSARY .................................................................................................................. 79


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Saudi Aramco DeskTop Standards ii

List of Figures

Figure 1. Spring-Pole Drilling Rig ................................................................................... 3

Figure 2. Chinese Pipeline ............................................................................................. 5Figure 3. Early Cable-Tool Drilling Rig ........................................................................... 6Figure 4. The Drilling Rig.............................................................................................. 10Figure 5. Well #1 Schematic ........................................................................................ 14Figure 6. The Drillstring ................................................................................................ 16Figure 7. Tool Joints..................................................................................................... 21Figure 8. Rock Compressive Strength - lbf/in

2............................................................. 23Figure 9. True-Rolling Tri-Cone Bit............................................................................... 26Figure 10. Off-Set Tri-Cone Bit..................................................................................... 27Figure 11. Kelly Through Rotary Table......................................................................... 32Figure 12. The Fluid System (Circulating System) ....................................................... 37Figure 13. Typical BOP Stack Configuration ................................................................ 46Figure 14. Typical Subsea BOP Stack Configuration................................................... 50Figure 15. The Drilling Rig Hoisting System................................................................. 51Figure 16. Single-Shot Target ...................................................................................... 54Figure 17. Whipstock Schematic.................................................................................. 58Figure 18. Positive Displacement Motor (PDM) Schematic........................................... 59Figure 19. Drilling Turbine Schematic ........................................................................... 59Figure 20. Cantilever Jack-Up Rig Schematic.............................................................. 76Figure 21. Slot Jack-Up Rig Schematic........................................................................ 77

List of Tables

Table 1. Operations for Well #1.................................................................................... 13Table 2. Drill Pipe Grade Code .................................................................................... 19Table 3. Common Tri-Cone Bit Sizes........................................................................... 25Table 4. Normal Weights and Rotary Speeds Steel Tooth Bits ................................. 29


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Saudi Aramco DeskTop Standards 3

INFORMATION

HISTORY OF DRILLING

The primary purposes of the drilling process are to gain access tosubsurface hydrocarbon fluids and to provide a flow path forbringing those fluids to the surface. Detailed geologic andphysical property information is a secondary benefit of the drillingoperation. Drilling may also serve the function of providing flowaccess for injection of external energy sources into thehydrocarbon reservoir to enhance recovery of the resource.

The Chinese were among the first to develop processes for thedrilling of a well. Their motivation, however, was not for productionof hydrocarbons but for production of salt water to obtain salt. In

approximately 256 BC, they developed the Spring-Pole Drillingconcept, as illustrated in Figure 1.

Figure 1. Spring-Pole Drilling Rig


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The Chinese took a large wooden timber, placed it on a pivot, andconnected a heavy bronze chisel or wedge back to the surfaceusing bamboo rods, hemp, or jute rope. They would then jump upand down on the wooden-timbered spring-pole, causing thewedge to impact the rock and fracture it. This was an inefficientprocess because it did not require the fracture of a large quantityof rock particles to cushion the impact. After drilling only a shortdistance, it was necessary to stop drilling, remove the drillingwedge from the well (trip out with the drilling tool), and then gointo the well with a bailer to bail out the cuttings so that drillingcould continue.

In more recent times, a bailer would be a heavy steel pipenormally 6 to 10 inches in diameter and 15 to 20 feet in length. Inthe bottom of this bailer was a one-way check valve. A typical

valve was a solid steel ball resting on shoulders at the bottom ofthe bailer, with a steel rod used as a stinger attached to the balland extending from the bottom of the bailer. The diameter of thesteel ball was measurably less than the inside diameter of thepipe, to provide space for rock cuttings to move up into the pipe.When it was necessary to bail out the cuttings, this bailer wasbrought over the wellbore and lowered on a cable. As it nearedthe bottom of the well, it was dropped. When the stingercontacted the bottom, it pushed the steel ball up inside the pipe.The impact of the heavy pipe on the bottom of the hole causedthe cuttings to move inside the bailer. When it was lifted off the

bottom, the heavy steel ball would close against the shoulders onthe bottom of the bailer, preventing the loss of rock cuttingstrapped inside. The bailer was returned to the surface and thecuttings were dumped. This process was repeated until onlynegligible cuttings remained. They would then trip in with thedrilling wedge, and drilling was resumed.


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Spring-Pole Drilling required three to four years to drill a well to adepth of 500 ft to 600 ft; yet, archaeologists have determined thatthe Chinese drilled some wells to depths as great as 3,000 ftusing this method. During the process of drilling wells to obtainsalt water, they discovered oil, leading to the development of aprimitive oil industry. The produced oil was used primarily asmortar for construction and sealant for vessels containing liquids.Figure 2 illustrates the Chinese wrapping large bamboo rods withlinen and sealing these pipelines with oil obtained from drillingoperations. These pipelines transported water for drinking as wellas for irrigation. The Chinese also had the first natural gaspipeline for transporting associated gas from the oil wells drilled.This gas was used for heating homes.

Figure 2. Chinese Pipeline

The Chinese had the first casing for the wells they drilled, usinglarge bamboo rods to line the wells and keep the walls fromcollapsing due to the soft materials near the surface.


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The second major historical event in drilling operations occurredwith the development of the steam engine. As shown in Figure 3,the steam engine modified the impact or percussion drillingprocess developed by the Chinese. It provided the necessarypower to rotate the power wheel with its eccentric, whichoscillated the walking beam, to mechanize the impact process.Though no longer a spring-pole technique, the drilling process stilloccurred by fracturing the rock it impacted. This led to Cable-ToolDrilling. Cable-Tool Drilling was the dominant process of thenineteenth century and has been significant in many areas duringthe twentieth century. Even though it is mechanized, Cable ToolDrilling is still a discontinuous process: drilling must be interruptedso that the bailer can be used to remove the well of cuttings beforedrilling is resumed.

Figure 3. Early Cable-Tool Drilling Rig

The third historical event in drilling was the development of theConventional Rotary Drilling process. The first well at Spindletopoutside Beaumont, Texas, was drilled in 1901 using theConventional Rotary Drilling technique. This event establishedrotary drilling as the twentieth centurys dominant method ofdrilling.


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A fourth major historical event is now occurring in drillingtechnology with the initiation of Bottomhole Assembly Drilling as amajor process. There are currently two dominant equipmentapproaches to Bottomhole Assembly Drilling:

Positive Displacement Motor (PDM)

Turbine Drill (Drilling Turbine)

These are often referred to as the downhole motor and thedownhole turbine. Over the next several decades, if the drillingprocess continues to be a mechanical process, variations ofBottomhole Assembly Drilling will probably replace ConventionalRotary Drilling as the dominant technique. There have been manymajor technical developments in the history of oil and gas welldrilling. A discussion of principles, practices, and equipment of

Conventional Rotary Drilling and Bottomhole Assembly Drilling willfollow in detail.

Roughnecks perform the labor for the drilling operation. They aresupervised by the Driller who also controls the operation of thedrilling equipment. Oil well drilling is a 24 hour-per-day operation.Onshore, the drilling crew typically works an 8-hour shift, morecommonly referred to as a tour (pronounced tower).Consequently, there are three roughneck crews per day, eachwith its own Driller. Offshore, the typical tour is twelve hours, withtwo roughneck crews per day, each with its own Driller.

In the offshore operation, these drilling crews may spend sevendays on the platform and seven days on shore leave; two weekson the platform and two weeks on shore leave; or other variationsof offshore assignments, depending on the country and companyemploying the drilling personnel. When on the offshore platform,the crews work twelve-hour tours, seven days per week.

The supervisor for the overall operation is the Toolpusher. Theroughnecks are responsible to the Driller, and the Driller isresponsible to the Toolpusher. The Toolpushers responsibility isto make sure that the well is drilled effectively and efficiently, thatequipment is maintained, and that the drilling program is followedwithin specified limits. The Toolpusher, Drillers, and roughnecksare usually employees of the drilling contractor. Contractorequipment and crews drill over 80% of the wells drilled today.


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The Drilling/Completion Engineer for the company whos well is tobe drilled will write the drilling/completion program for thatparticular well. The contractors responsibility is to drill the wellwithin the specified limits of the program. Variations from thedrilling/completion program are typically permitted only insituations where personnel safety or control of the well is inquestion. There will generally be a company person, at thewellsite, representing the company whose well is being drilled.This Company Man may be the Drilling Engineer, a companyToolpusher, Drilling Supervisor, or other employee that thecompany assigned to this responsibility.

Roustabouts are the general laborers of the oil field. In anonshore operation, the roustabouts maintain and paint equipment,dig ditches, lay pipelines, serve as welders helpers, or perform

other necessary labor. On the offshore platform, the roustaboutsmaintain and paint equipment, clean up, serve as weldershelpers, and perform other necessary labor.

The supervisor of the roustabouts is the Gangpusher. Hisresponsibility is to push the roustabout gang. In many offshoreoperations, the Crane Operator is responsible for the roustabouts.


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CONVENTIONAL ROTARY DRILLING

The following sections will be discussed:

Drilling rig operations Drilling rig subsystems

Drilling techniques

Drilling Rig Operations

Many consider the drilling rig to be the structure, or the derrick,itself. As shown in Figure 4, however, the rig is the completedrilling system, including the derrick, substructure, engines,pumps, blowout prevention system, drill pipe, and othernecessary accessories for the drilling operation.


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Figure 4. The Drilling Rig


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The only equipment changed from one well to the next will bethose accessories necessary for that particular drilling operation,such as drill bits, chemicals for drilling fluids, and special drillingassembly systems.

To illustrate drilling considerations and technology, assume that awildcat well has been drilled after selecting the drill site, usingseismic information obtained during a seismic survey. Thisonshore well revealed the presence of hydrocarbon in asubsurface sedimentary rock. Information gathered from the rockcuttings, well logs, and cores indicated that there was ahydrocarbon presence sufficient to justify further activity.

Appraisal wells were drilled to define the hydrocarbon presence,and this accumulated information indicated the existence of amajor hydrocarbon reservoir at a depth of approximately

10,000 ft. On the basis of this information, development shouldproceed.

Appropriate company personnel submitted a development plan forthe reservoir, including a drilling/completion program prepared bythe Drilling/Completion Engineers for a typical development wellidentified as Well #1. The drilling/completion program includedall necessary details sufficient for the contractor to submit a bid onthe project. A summary in overview of this basicdrilling/completion program that the Engineer developed follows:

Spud the well with a 36" hole opener to a depth of 300 ft. This

hole opener is a device designed specifically to open the holeto solid rock through the unconsolidated materials near thesurface. This may be an auger type device, a scoop device,or even a drill bit.

Once the hole has been opened to the 300-ft depth, run a 30"conductor pipe from the 300-ft depth point back to the surface.These depths to which casing is set in the drilling/completionprogram are called casing points. This conductor pipe mayalso be called the conductor, conductor casing, conductorstring, or, in an offshore operation from a sea floor-supportedstructure, the drive pipe.


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The primary difference between an onshore welldrilling/completion program versus an offshore program is howthe conductor casing is set. In the onshore operation it isdrilled for. In the offshore operation, from a non-floatingplatform, a pile driver typically drives the casing into the seafloor to its casing point. When operating offshore from afloating platform such as a semisubmersible or a drill ship, theconductor casing is typically drilled for, washed in with a jetnozzle bit, or a combination of the two methods.

Once the conductor pipe has been run, the wellbore simplycollapses around the casing. It is not normally cemented.Materials may be dumped around the casing once it has beenset in place, to fill the space and hold the conductor pipe inplace. In an onshore operation, a cement pad might be poured

around the top of the casing, so that there will be a clean workarea around the wellhead for further operations as the well isdrilled, completed, and put in production.

Once the conductor casing has been set, the program thencalls for the contractor to drill to a casing point of 2,000 ft witha 26" bit (1,700 ft beneath the casing point of the conductorpipe).

After drilling with the 26" drill bit to the depth of 2,000 ft, run a20" surface string of casing from the casing point back to thesurface, and cement this surface string all the way on the

outside of the casing. The surface string is always cementedfrom its casing point back to the surface.

After the cement has set for the surface string, drill to a casingpoint of 6,000 ft with a 17-1/2" drill bit.

After drilling to the 6,000-ft casing point, run a 13-3/8"intermediate string of casing from the casing point back to thesurface. Cement the intermediate string from the casing pointback 5,000 ft uphole to within 1,000 ft of the surface (cementthe bottom 5,000 ft of the 13-3/8" intermediate string, whichmeans that this casing will be cemented back 1,000 ft inside

the surface string). Engineering calculations determine that itis unnecessary, in this particular well, to cement theintermediate string of casing all the way back to the surface.


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When the cement has set for the intermediate string of casing,drill to total depth (TD) of 10,000 ft with an 8-3/4" drill bit.

Run a 7" production string of casing to the total depth of

10,000 ft and cement the bottom 5,000 ft of this productionstring (cement back 1,000 ft inside the intermediate string).

The drilling and casing operations for Well #1 are now complete.The following is a summary of these operations:

Depth Bit Size Casing Size Object

300 ft 36" 30" Conductor pipe

2,000 ft 26" 20" Surface string

6,000 ft 17-1/2" 13-3/8" Intermediate string

10,000 ft 8-3/4" 7" Production string

Table 1. Operations for Well #1

A schematic cross-section of the completed well is shown inFigure 5.


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300 ft36 Bt

20 O. D. Casing

2000 ft

26 Bt

13 3/8 O. D. Casing

6000 ft

17 1/2 Bt

7 O. D. Casing

10000 ft

8 3/4 Bt

CL

30 O. D. Casing

Figure 5. Well #1 Schematic


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Drilling Rig Subsystems

The Conventional Rotary Drilling system is divided into fivesubsystems:

The Drillstring (Rotating System)

The Fluid System (Circulating System)

The BOP System (Blowout Prevention System)

The Hoisting System

The Power System

The Drillstring

(Rotating System)

The drillstring is suspended from the hoisting system into thewellbore. Typical components of the drillstring, as illustrated inFigure 6, from the bottom of the well back to the hoisting systemare:

Bit

Drill collars

Drill pipe

Kelly

Swivel


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Figure 6. The Drillstring

Dependent upon the particular drilling situation, additionalcomponents such as stabilizers, centralizers, reamers, jars, andshock absorbers, might be included in the drilling assembly.


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The running and cementing of the casing is considered to be apart of the completion operation. From the previous procedure,the well is drilled and casing is run and cemented in stages, sothat these processes occur at different times during theoperations.

Following is a discussion of the basic procedure for the drillingand completion stages of this well. Factors which determine thecasing points and the functions of the various casing strings areexplained in the discussion of drilling and completion operationsin Module 6.

Introduction - When the Drilling/Completion Engineer hascompleted the program for this well, it is submitted to drillingcontractors for bidding. If there is an acceptable bid, a contract issigned and the operation proceeds. The actual drilling/completionprogram submitted to the contractor for the well is far moredetailed than the summary listed. Since this is a developmentwell, the engineer will know the type of rock which must be drilledthrough to reach the reservoir, the pressures he will encounter indrilling, contaminating fluids he must drill through (such as H2S),

reservoir rock properties, and reservoir fluid properties.

The drilling program will include bit type at various depths, therotary speed and bit weight to use, jet nozzle diameter, drillingfluid flow rates, pump discharge pressures, drilling mud densityand chemistry, and other such specifications as may be

necessary for efficient, effective drilling and completion of thedevelopment well. A discussion of these topics will follow.

Before accepting a contractor proposal, the company engineermay request detailed specifications for the drilling rig to be used.The engineer could therefore check power availability, pump flowrates and discharge pressures, drillstring strength, and othercharacteristics that might be significant. It is important that thedrilling rig accepted not be undersized, but it should also not besignificantly oversized for this particular well operation.


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In the discussion to follow, there will be references to the drillingand completion of this well, to illustrate various operations. Thewell will be referred to as Well #1. After considering thedrilling/completion program for Well #1 and the contractorproposal, a contract is signed. The company Drilling/CompletionEngineer has carefully considered the contractor drilling rigselected to drill the well and has studied its past performance andengineering specifications before agreeing to the contractconditions. The rig will be called Contractor Drilling Rig #90.

The drillstring consists of the components shown in Figure 6. Afterdrilling and casing operations have proceeded on Well #1 throughthe running and cementing of the intermediate casing string, Rig#90 drills the well at a depth of 7,000 ft with the 8-3/4" diameterdrill bit. At this depth, there will be 7,000 ft of drillstring in the well.

Only about 1 ft of the drillstring involves the bit. The kelly is 40 ftlong if drilling onshore or offshore from a non-floating (sea floorsupported) platform, or 46 ft or 54 ft when drilling offshore from afloating platform (semisubmersible or drill ship). The drillstringtherefore consists essentially of 7,000 ft of drill pipe and drillcollars when drilling at the depth of 7,000 ft.

Drill Collars and Drill Pipe are both pipe, but there physicalproperties are significantly different. A joint of drill pipe is 30 ftlong and a drill collar is 30 ft long. To illustrate the differencebetween drill pipe and drill collars, consider specifications for Rig#90. The drill pipe is 4-1/2" O.D, 3.64" I.D., with a nominal weightof 20 lbf/ft. The steel wall thickness is therefore 0.43". A 30-ft joint

weighs 600 lbf. As these specifications indicate, this is a typical

pipe. When the specifications for the drill collars are checked, a30-ft drill collar has a 6-1/2" O.D., 3-1/2" I.D., with a nominalweight of 80 lbf/ft. The steel wall thickness, therefore, would be 1-

1/2". As is obvious from these specifications, a drill collar is anextremely thick walled, heavy pipe. A 30-ft drill collar weighs2,400 lbs.


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The drill pipe and the drill collars are manufactured using high-grade alloy steel with various minimum yield strengths, dependingon the grade of steel selected. This is illustrated for drilling pipe inTable 2.

GradeMinimum Yield

(psi)Symbol

N-80 80,000 N

D 55,000 D

E 75,000 E

C-75 75,000 C

X-95 95,000 X

G-105 105,000 G

P-110 110,000 P

S-135 135,000 S

V-150 150,000 V

Table 2. Drill Pipe Grade Code

When comparing steel used in drill pipe and drill collars withstructural steel, typical structural steel has minimum yield strengthof approximately 60,000 psi. This indicates that typical structuralsteel can withstand loading in tension or compression up to60,000 psi without permanent deformation. When the load isremoved, the steel member will return to its original, undeformed

dimensions. However, if the minimum yield strength is exceeded,the steel member will receive a permanent deformation.


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For most structures, including drillstring members, yielding(permanent set or deformation) is failure. Common grades of drillpipe steel used in drillstring components are E Grade (75,000 psiminimum yield strength), G grade (105,000 psi minimum yieldstrength), and S Grade (135,000 psi minimum yield strength). Drillcollar steel will have similar properties.

Higher grades of steel are used in drillstring components than inmost common structures. This is necessary because of theextremes of conditions encountered during the drilling operation.Primary design considerations for the drillstring are:

Axial loading in tension

Axial loading in compression

Torsional loading

Burst pressures

Collapse pressures

Fatigue loading

Corrosion

Abrasion

Failure in bending as a thin-walled cylinder

Failure in bending as a thin-walled cylinder results from extreme

deviation of the wellbore. This extreme seldom exists so that suchfailure rarely occurs. The other factors, however, are of primaryimportance in drillstring design.

The joints of drill pipe and drill collars are connected by threadedconnections, as shown in Figure 7. These connections are calledtool joints. In discussions regarding the drillstring, there will becomments regarding the drill pipe, drill collars, and tool joints, as ifthe tool joints are pieces of equipment independent of the drillpipe and drill collars. These threaded connections, however, arean integral part of each joint of drill pipe and each drill collar.These connections are locations of stress concentration in thedrillstring. If there is failure, it will most likely occur at the tool

joints.


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Figure 7. Tool Joints

To increase the strength at the connections, a stronger alloy steelis used for the tool joints than for the drill pipe or drill collar body.The tool joint is attached by friction welding. The O.D. of the tool

joint and the ends of the drill pipe are greater than the O.D. of thedrill pipe body in order to increase the steel wall thickness and

accommodate the welding process. This greater O.D. is notnecessary for the drill collars since they already have a large O.D.and steel wall thickness. The drill pipe or drill collar body isrotated at high RPM in one direction, and the tool joint is rotatedat high RPM in the opposite direction. When they are pressedtogether, the heat generated by friction results in the necessarywelded connection. Since the O.D. of the tool joints is greaterthan the O.D. of the drill pipe body, these tool joints are known asexternally upset or e.u. tool joints. The shoulders at the largerdiameter section on the ends of a drill pipe joint serve variousbeneficial functions when activating the BOP system, removing

the drillstring from the well (tripping out) to change a dull bit, andreturning the drillstring to the well (tripping in) with a new bit. Thecombination of tripping out and tripping in is referred to as a roundtrip.


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During the round trip, pipe elevators remove the drillstring fromthe well. These elevators latch onto the top of the drillstring, usingthe shoulders of the externally upset tool joints as seats.

The connections would not normally be strengthened bydecreasing the inside diameter. If so, there would be a flowrestriction every 30 ft within the drill pipe, resulting in a Venturieffect. The results would be considerable pressure loss and pipeerosion at the tool joints during drilling, since drilling fluid ispumped down the drillstring. The joints of drill pipe and drill collarsrun in the drillstring box end up and pin end down (internalthread up and external thread down).

There are many downhole parameters that affect the drillingoperation, including:

Characteristics of the rock which must be drilled Subsurface fluid pressures

Subsurface fluid temperatures

Downhole contaminants, such as H2S

Physical orientation of the subsurface rocks

Other rock characteristics, such as soft unconsolidatedmaterials tending to collapse into the wellbore, and rocks withabrasive characteristics

The Drilling Engineer determines many drilling parameters torespond to these downhole conditions and optimize the drillingoperation. Four significant parameters are

Bit type

Rotary speed of the bit (RPM)

Bit weight (force causing the rotating bit to penetrate theformation)

Fluid system

The Drilling Engineer can affect other parameters that may be ofsignificance, depending on the conditions encountered in drilling aparticular well. Chemical considerations of the drilling fluids andresponse to downhole chemicals encountered may be significantin some wells.


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Bit If the well being drilled is a development well, the DrillingEngineer will be able to anticipate the types of rock to be drilledthrough at various depths. The type of drill bit selected willdepend on the rocks to be drilled. A round trip must be madewhen a bit is changed. Depending on depth, this may requireseveral hours, so it is not practical to change the bit each time anew rock formation is encountered. The Drilling Engineer willselect the bit to optimize the drilling process in consideration ofrocks that will likely be drilled through during a particular bit run.

During the drilling operation, a drilling fluid is pumped into the topof the swivel through the swivel, kelly, drill pipe, drill collars, outthe jet nozzles of the drill bit, and returns up the annulus (thespace outside the drillstring) back to the surface, carrying rockcuttings removed by the bit. Drilling fluid could be a gas or a

liquid. If it is a liquid, it is called mud, even if it is pure water.

The drilling process occurs by mechanical action: normally byfracturing, abrading, or shearing the rock. Depending on the typeof rock to be drilled and the type bit selected, the tensile,compressive, or shearing strength of the rock will be primaryconsiderations. Figure 8 shows compressive strengths of variousrock samples.

Figure 8. Rock Compressive Strength - lbf/in2


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Many bit types are available for drilling. Four types that aredominant in todays industry will be discussed in some detail.

The milled tooth tri-cone rock bitis a roller cone bit. It gets its

name from drilling rocks and having each of its three cones milledfrom a single block of metal. The teeth are therefore of the samemetal as the bit body. Howard Hughes, Sr. patented the conceptfor this bit in 1909, revolutionizing oil well drilling in this century.

The roller cone bit is a precision machine. It is not a gear typesystem, because the cones are not in contact with one another.Each cone is designed and manufactured to withstand extremedynamic conditions. Each cone rotates independently of the othercones as the drillstring is rotated from the surface. When thedrillstring (or rotor, in the case of Bottomhole Assembly Drilling)rotates, the cones roll on the bottom of the hole. When force isapplied during rotation, as a tooth comes in contact with thebottom of the hole, the force acting on the bit results in thefracturing of the rock, creating chips (cuttings). The tooth will thenlift from the bottom due to the rolling process. The fluid system willremove the rock cuttings and carry them back to the surface.

The Conventional Rotary System is a continuous system, unlikethe discontinuous system of Cable-Tool Drilling. In theConventional Rotary System, the drilling fluid removes thecuttings and carries them back to the surface as drilling occurs,whereas in Cable-Tool Drilling, it is necessary to stop drilling and

use a boiler to remove the cuttings before drilling can beresumed.


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These bits are available in many sizes, as illustrated in Table 3.They are designed for drilling various types of rocks. A jet nozzleinsert is placed in the bit body between each cone combination.The drilling fluid flows through these nozzles to clean the bottomof the hole. Jet nozzle diameter is always expressed in 32nds ofan inch. The Drilling Engineer selects the nozzle size in order tooptimize the drilling fluid (hydraulics) system. He selects thenozzle diameter, along with the volume flow rate of the drillingfluid in gpm (gal/min) for a particular rig drilling at a particulardepth, in order to optimize bottomhole cleaning.

COMMON TRI-CONE BIT SIZES

3-3/4" 6" 7-7/8" 9-7/8" 14-3/4"

3-7/8" 6-1/8" 8-3/8" 10-5/8" 17-1/2"

4-1/8" 6-1/4" 8-1/2" 11" 20"

4-3/4" 6-1/2" 8-3/4" 12-1/4" 24"

5-7/8' 6-3/4" 9-1/2" 13-1/2" 26"

13-3/4"

Table 3. Common Tri-Cone Bit Sizes

An important consideration during drilling is the bit gaugediameter. As abrasive rocks are drilled, there will be a tendency toabrade the bit, reducing its O.D., or gauge diameter while drilling.The intolerable result will be a tapered hole. When the bit wearsout, it will not be possible for the new bit to return to the depth

drilled. Tungsten carbide steel inserts are normally placed aroundthe gauge diameter, to resist abrasion and maintain the diameter.


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The milled tooth bit is designed to drill in rock that is best drilledby fracturing. When drilling in such rocks, the cones will be truerolling. In the true rolling bit (Figure 9), each cone axis intersectsthe drillstring axis at a common point. These bits may bedesigned to drill soft, pliable rock by offsetting the cone axis asshown in Figure 10. This type of bit, however, should not be usedin abrasive rock, because this fracture/shearing actioncombination will produce rapid abrasion of the bit.

Figure 9. True-Rolling Tri-Cone Bit


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Figure 10. Off-Set Tri-Cone BitThe insert bit or button bitis both a tri-cone bit and a roller conebit. The cone body is of a different metal than the teeth. Theteeth have been inserted into the cone body and are usually ahard alloy of tungsten carbide steel. The teeth are available invarious shapes and are usually more blunt than the teeth of themilled tooth bit. The insert bit is designed to drill in harder rockthan is the milled tooth bit. The drilling action is still a fractureprocess, but more of a crushing action than with the milled toothbit. Generally, if drilling is attempted with a milled tooth bit in thetype of rock that an insert bit is designed to drill, the force requiredwill destroy the bit instead of drilling the rock.

The diamond bithas commercial grade diamonds imbedded in thebit body and is available in various designs. This bit drills with an

abrasive action and is designed for drilling extremely hard rocksuch as metamorphic quartzite.

A diamond core bit in use leaves a central rock cylinder that isusually four inches to six inches in diameter. This rock cylinder, orcore, is collected in a core barrel above the bit. Externally, thecore barrel resembles a drill collar. Internally, however, the drillingfluid flows down the inside of the drillstring through an annulusinside the core barrel, but outside the core collector. The fluidflows through the bit to carry the cuttings outside the drillstringback to the surface. Dependent upon the core barrel design, oftena rubber, vinyl, or plastic sleeve will fold down over the core toseal and protect it from further drilling fluid contamination andnatural fluid loss. Some core barrels collect the core within asurrounding sponge system. These precautions are necessary,because it is best to remove the core back to the surface withoutmajor damage or contamination from external fluids and withminimum loss of natural fluids. This process is difficult, since thecore is taken from reservoir fluid pressure to atmosphericpressure. Attempts are therefore made to minimize contaminationby drilling fluids and to retain natural fluids as the core isremoved. Coring is expensive; each time a core is collected, a tripmust be made to remove the regular drill bit, and a round tripmust be made to take the core.


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Typical cores may be from 30 feet to 90 feet in length. In isolatedinstances, longer cores have been taken. Longer cores aredesirable, because they minimize trip time required in coringthrough a reservoir rock. After the core is returned to the surface,it is sent to the laboratory for analysis. As discussed, coreanalysis provides extremely valuable information for reservoiranalysis. Core bits may be of types other than diamond bits.

The newest of the four dominant bits is the PCD or PDC bit. Thisbit was developed in the 1970s to drill in pliable rock formationsthat, although solid, are highly plastic or deformable. They will notfracture when drilled with a milled tooth or insert bit.

A diamond bit would simply gum up or ball up with this pliablematerial, but the PCD bit drills with a shearing action. Small disksare fabricated from a synthetic diamond material and are attachedto a base that is attached to the bit body. When the bit rotates,this diamond disc will shear the rock. This material resulted in thename PCD (polycrystalline diamond) or PDC (polycrystallinediamond compact) bit. In general, this bit is referred to as acompact bit and is available in various designs. It is nowdeveloped for both soft rock and hard rock drilling. The compactbit is the result of evolution in bit design, originating from earlydrag bits or fishtail bits, which drilled primarily with a shearingor scraping action.

After selecting the bit type, based on the formations to be drilled,

the engineer will then select the rotary speed and bit weight.Table 4 provides recommended values for several bit types. Bitweight is often given in thousands of pounds per inch of bitdiameter.


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Type

Normal Weight,

lbf/in. Bit

Diameter

kgf/mm

Bit Diameter

Normal

Rotary Speed

(RPM)

J1 3,000 - 5,000 55 - 90 120 - 90

X3A, OSC3AJ 3,000 - 5,000 55 - 90 250 100

J2 3,500 - 5,500 60 - 100 120 - 70

X3, OSC3J 3,500 - 5,500 60 - 100 140 - 90

J3 3,500 - 6,000 60 - 110 100 - 60

OSC1GJ 3,500 - 6,000 60 - 110 125 - 70

JD3 3,500 - 6,000 60 - 110 100 - 60

J4, JD4 4,000 - 8,000 70 - 140 100 - 40OWVJ, OW4J 4,000 - 8,000 70 - 140 100 - 40

J7 4,500 - 8,000 80 - 140 80 - 45

J8, JD8 6,000 - 8,000 110 - 140 70 - 50

W7R2J 4,500 - 8,000 80 - 140 80 - 45

WO *8,000 - 15,000 *3600 - 6800 kgf 60 - 40

*Total Load

Table 4. Normal Weights and Rotary Speeds Steel Tooth Bits

Rotary speeds are expressed in RPM (revolutions per minute).For Conventional Rotary Drilling, the speeds usually vary from aminimum 30 RPM to a maximum 250 RPM. The most commonranges of rotary speed are 60 RPM to 120 RPM (1 to 2revolutions per second).

Bit weight will normally vary from a minimum of 0 to a maximumof 100,000 lbf. More common ranges may be 10,000 lbfto 60,000

lbfof bit weight. Bit weight is not the weight of the bit, but it is theweight on the bit. Bit weight is applied by the weight of the drillcollars. The drill pipe does not have sufficient strength to beloaded in compression. Drill collars, however, do have propercharacteristics to be loaded in compression, as indicated by theirlarge O.D. and steel wall thickness. They are designed to serveas a column type support and therefore may apply a compressiveload.


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In engineering terminology, the drill pipe does not have a properslenderness ratio to serve as a column type support, while the drillcollars do have a proper ratio. Sufficient drill collars are connectedby their threaded tool joint connections on top of the bit, to providethe necessary bit weight. A common rule used in drilling is that bitweight should not exceed 80% of drill collar weight.

Assume that Well #1 is being drilled at a depth of 8,000 ft with an8-3/4" milled tooth bit, with a rotary speed of 60 RPM and a bitweight of 32,000 lbf. The weight of drill collars to be used in this

case should be 40,000 lbf. If the drill collars weigh 80 lbf/ft, this

means that 500 ft of drill collars are required. At 30 ft per drillcollar, this means that 16-2/3 drill collars should be used.Seventeen drill collars will therefore be connected above the bitfor the bit weight. At 30 ft per joint, 510 ft of drill collars will be run,

with a total weight of 40,800 lbf. Since the well is filled with drillingfluid, this provides an excess of 8,800 lbfabove the bit weight, to

accommodate the buoyant effect which is reducing the equivalenteffective weight of the drill collars available for bit weight, plus asafety factor. With 510 ft of drill collars in the well, drilling at adepth of 8,000 ft will require 7,490 ft of drill pipe to connect backto the surface. At 30 ft per joint, 249-2/3 drill pipe joints will berequired. The actual number of joints will be 249, since the extra20 ft is taken up by the kelly. There will be 510 ft of 80 lb f/ft drill

collars in the well, and 7,470 ft of 20 lb f/ftdrill pipe. The drill

collars will therefore weigh 40,800 lbfand the drill pipe will weigh

149,400 lbf. The total effective weight of the drillstring will be

approximately 190,200 lbfplus the weight of the bit, the kelly, the

swivel, and any subs or other bottomhole assembly componentsthat might be in the well, less buoyancy, because the well is full ofdrilling mud. A sub is a short drill collar (a drill collar less than 30 ftin length).

The Driller needs to calculate only the number of drill collarsrequired. As indicated, the excess weight of drill collars is used asa safety factor as well as to allow for the buoyancy effect on drillcollar weight available for bit weight. The only calculationnecessary for the Driller is to make certain that the bit weight doesnot exceed 80% of the drill collar weight. In this example, theDriller simply makes sure that 17 drill collars are connected abovethe bit in the drillstring. He then continues to trip into the well,adding drill pipe to total depth. For each stand of pipe added, theincreased weight of the drillstring is indicated on his MartinDecker.


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Martin Decker is the name of one company manufacturing thelarge circular dial gauge at the drillers station which monitorshoisting pullback load, or hook load. For each stand of drill pipeadded, the hook load increases due to the increased weight of thedrillstring. At some point, the load decreases as a stand of pipe islowered. This indicates that the drillstring is on the bottom of thehole, which is now supporting a portion of the weight. The Drillerwill then lift the drillstring with the hoisting system and read themaximum reading for hook load. He is determining the weight ofthe drillstring suspended in the well. This reading considers notonly the weight of the drill collars, drill pipe, bit, kelly, swivel, andother accessory equipment, but also the buoyant force, becausethe wellbore and drill pipe are filled with drilling mud.

After this reading is taken, the drillstring is rotated at its desired

rotary speed (60 RPM in this example). With the drillstringrotating, the Driller then lowers the drillstring with the hoistingsystem until the hook load reduces by 32,000 lbf. Drilling is now

proceeding at the 8,000 ft depth with a rotary speed of 60 RPMand a bit weight of 32,000 lbf. The hoisting system, pulling back

on the drillstring, is assuring that the entire drill pipe is in tensionwhile drilling. The neutral point of the drillstring must be in thedrill collars. The neutral point is that point below which thedrillstring is in compression and above which it is in tension. Thedrill collars can withstand a compressive or tensile load, but thedrill pipe must never be in compression. If it should be placed in

compression, it will bend, resulting in a highly deviated wellborewhere rotation will cause fatigue failure of the drillstring. Whenfailure occurs, it is necessary to go fishing in order to recoverequipment lost in the hole. If the Driller cannot recover theequipment (catch the fish), it must be abandoned and bypassedby sidetracking.

Kelly The kelly is connected above the top joint of drill pipe inthe drillstring. It differs from a joint of drill pipe in two ways:

The kelly is longer. When drilling onshore or offshore from anon-floating (sea floor supported) platform, a 40 ft kelly is

used. When drilling offshore from a floating platform(semisubmersible or drill ship), a 46 ft or 54 ft kelly is required.This longer kelly is necessary to compensate for the heaveresponse to wave action during the drilling operation.

The kelly is square or hexagonal in external perimeter, whiledrill pipe is circular in external perimeter.


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The kelly passes through the rotary table in the plane of the rigfloor. The kelly bushing, which is on the kelly and sets down intothe rotary table, is free to slide along the kelly. On the bottom ofthe kelly is its externally upset tool joint. If the kelly bushing is ofsquare bottom design, it sets into a square hole in the rotarytable. The drilling rig power system rotates the rotary table at thedesired speed. If the kelly is square, it passes through a squarehole in the kelly bushing. If the kelly is hexagonal, it passesthrough a hex hole in the kelly bushing as shown in Figure 11.

Derrick or Mast

Traveling block

Drilling hook

Swivel

Kelly

Rotary table

Blowout Preventer(BOP)

Wireline

Figure 11. Kelly Through Rotary Table


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The first function of the kelly/kelly bushing/rotary tablecombination is to impart rotation to the drillstring and therefore tothe drill bit. When the drilling rig power system applies torque tothe rotary table, it in turn applies torque to the square bottomedkelly bushing which applies torque to the square or hex kelly,rotating the kelly and therefore the drillstring and bit. This simplemechanical linkage is how the drillstring and drill bit rotate.

In the pin kelly bushing design, four steel pins at the corners ofthe bushing are set down into the rotary table, providing themeans for transmitting torque from the rotary table to the kellybushing. Both square and pin kelly bushings are common.

The second function of the kelly/kelly bushing/rotary tablecombination is to permit the Driller to maintain bit weight duringdrilling. With this combination, he lowers the kelly through therotating kelly bushing while drilling occurs. When the Driller setsthe hoisting system so that proper bit weight is being applied atthe desired rotary speed, the hoisting system will normally be seton automatic. This means that, as drilling occurs and rock supportis being removed below the bit, the hoisting system willautomatically lower the drillstring through the rotating kellybushing to maintain bit weight. Since the kelly bushing istransmitting torque to the kelly, extreme sliding friction will result.There will normally be rollers within the kelly bushing to reducewear on the kelly by converting from sliding friction to rollingfriction.

To the side of the drilling rig floor, a casing usually extends 5 or 6feet above the rig floor at a slight angle from the vertical. Thisapproximately 10" diameter casing is called the rathole. Whentripping into or out of the well, the kelly is set aside in the ratholefor storage. After each 30 ft of drilling, it is necessary to add a jointof drill pipe, or make a connection. After the Driller adds that

joint, he brings the next joint onto the rig floor and stores it in thevertical mousehole adjacent to the rotary table (Figure 11).


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When it is necessary to make a connection, the Driller lifts thedrillstring with the hoisting system. When the e.u. tool joint at thebottom of the kelly comes through the rotary table, its shoulderhangs on the bottom of the kelly bushing, pulling it out of therotary table. The drillstring is raised until the e.u. tool joint on thetop of the first joint of drill pipe appears above the rotary table.The roughnecks then drop the slips into the rotary table aroundthe smaller diameter body of that top joint of drill pipe. Slips are aset of hinged wedges that are used to wedge the drillstring intothe rotary table. With the slips in place, the Driller lowers thedrillstring with the hoisting system, wedging the top of thedrillstring into the rotary table suspending the weight of thedrillstring from the rotary table. The rotary table is designed tosupport such a load.

With the drillstring hanging from the rotary table, the roughnecksdisconnect the kelly from the top of the drillstring and bring it overthe next joint of drill pipe stored in the mousehole. When thatconnection is made, the Driller lifts the kelly and connected next

joint of pipe with the hoisting system, brings it back over thedrillstring, and the roughnecks make the connection of the pin atthe bottom of that next joint of drill pipe into the box at the top ofthe drillstring. The Driller then picks up with the hoisting system,pulling the slips out of the rotary table. He then lowers thedrillstring, setting the kelly bushing into the rotary table and startsrotation at the desired rotary speed. He now lowers the drillstring

with the kelly sliding through the kelly bushing, until bit weight hasbeen achieved. The connection has been made.

Swivel - The top component of the drillstring is the swivel, whichserves several important functions. The swivel is the mechanismby which the drillstring is suspended from the hoisting system intothe wellbore. The drilling hook of the hoisting system latches intothe bale on top of the swivel, suspending the drillstring into thewellbore. The swivel also makes the necessary transition from thenon-rotating hoisting system to the rotating drillstring. The top ofthe swivel does not rotate, but the bottom does.


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Connected into the top of the swivel is the rotary hose. Thisreinforced, flexible hose is usually 3" to 5" in diameter and 55 feetin length. The drilling fluid is pumped into the drillstring throughthe rotary hose and flows through the swivel, kelly, drill pipe, drillcollars, out the jet nozzles of the bit, and back up the annulus,where it is exhausted at the surface to atmospheric pressure.Since, during drilling, the drilling fluid always exhausts to 0 psig(atmospheric pressure), drilling operation pressures are almostalways expressed as gauge pressures (psig). Since the drillingfluid enters the non-rotating top of the swivel and exits the rotatingbottom of the swivel, the fluid pressure seal within the swivel is anextremely important feature. Differential pressures of severalthousand psi exist across this seal.

Of the drilling equipment discussed, many drilling operations

worldwide are replacing the kelly/kelly bushing/rotary table,especially in operations offshore.

The new system that is replacing the kelly/kelly bushing/rotarytable combination, to impart rotation to the drillstring, is the powerswivel. This is known as a top drive system. In this system, theswivel is serving the additional function of imparting rotation to thedrillstring and therefore to the bit. It is a motor with an armaturemade to rotate as power is applied to it, transmitting torque forrotation to the drillstring. The power swivel is normally electric orhydraulic powered.

When drilling with a top drive system, the kelly/kellybushing/rotary table system is no longer required and is not ofuse. These components are still available, however, if required,and may also serve the very different function of steering thedrillstring when directionally drilling with a Bottomhole Drilling

Assembly.


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The power swivel has been available in the industry for manyyears, primarily for completion and workover rigs, but not fordrilling rigs. Most major oil companies will only contract with anoffshore contractor if the drilling system is a top drive system. Thissystem has several advantages, one of which is that drill pipe canbe added a stand at a time instead of a joint at a time, reducingthe connection time by two-thirds. The Driller can now drill 90 ftbefore making a connection, rather than 30 ft. This is not practicalwith the kelly, because it would be necessary that the kelly beover 90 ft long and that the drilling rig be over 180 ft tall. A secondadvantage of the top drive system is that drilling fluid can becirculated between stands to keep the wellbore clean during atrip. When drilling with a kelly system, this is not practical sincethe kelly is stored in the rathole during the trip.

A major concern during drilling is that the wellbore might collapseon the drillstring. In the case of Well #1, while drilling at a depthof 8,000 ft with the 8-3/4" drill bit, with 32,000 lbfof bit weight,

there would be 510 ft of 6-1/2" drill collars above the bit. Theannular space outside the drill collars is slightly more than 1"wide. If the wellbore should collapse, the drillstring might stick inthe wellbore and may not be retrievable. One of the most likelytimes for wellbore collapse is during a round trip to change the bit.Since the top drive system may be used to keep the wellboreclean during a trip, there is less possibility of sticking the drillstringdue to wellbore wall collapse.

From these discussions, it is obvious that the drillstring is adynamic, flexible system. It is important to have the capabilityboth of monitoring and controlling that flexibility, to control thetrajectory of the wellbore.

The Fluid System

(Circulating System)

When drilling with a liquid as the drilling fluid, that liquid is referredto as drilling mud, even though it may be pure water. Thechemistry of drilling muds is a scientific specialty in itself.

Downhole chemistry during drilling may be critical to the drilling,completion, and production operations.


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The drilling fluid system or circulating system can fulfill manyfunctions, depending on conditions encountered downhole whiledrilling. The flow system is illustrated in Figure 12. If the wellbeing drilled is a development well, those functions can usually beanticipated and planned for in the drilling program.

Figure 12. The Fluid System (Circulating System)


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Seven of the more commonly expected functions of the fluidsystem will be considered. If the first two of these functions arethe only ones to be fulfilled, the well may be drilled using eithergas or liquid as the drilling fluid. In most cases, gas is preferable.If any of the last five functions must be fulfilled, with oneexception, the drilling fluid must be a liquid (mud). Thesefunctions are

1. Bottomhole cleaning.

As drilling occurs, rock particles are mechanically removedfrom the formation being drilled. Drilling fluid carries thesecuttings up the annulus back to the surface. Therefore, theConventional Rotary Drilling process is a continuous processas compared to Cable-Tool Drilling, where it was necessaryto stop drilling and bail out the cuttings. In ConventionalRotary Drilling, the fluid system removes the cuttings asdrilling progresses. When drilling with a mud, the minimumreturn velocity in the annulus must be at least 120 ft/min (2ft/sec) in order to carry the cuttings from the wellbore to thesurface. Lesser minimum velocities would result in cuttingfallout and the possibility of sticking the drillstring becausecuttings would accumulate in the annulus. This minimumvelocity would occur in the largest diameter portion of thewell above the drill bit, around the smallest diametercomponents of the drillstring, usually around the drill pipe.Consequently, the average return velocity to the surfacewould be greater than 2 ft/sec. This cleaning function may befulfilled by either gas or mud.

2. Cooling and lubricating the bit.

The drill bit operates under extreme dynamic and loadconditions. The considerable heat generated must bedissipated, and the abrasive environment must beminimized. In some instances, a gas does not have sufficientheat capacity to dissipate the heat, and a mud is required.


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3. Supporting and stabilizing the wellbore to prevent collapse.

As drilling proceeds through hundreds of feet of subsurfacerock, many rock beds may not be well consolidated (may not

have undergone sufficient lithification). These beds will tendto collapse into the wellbore, increasing the possibility ofsticking the drillstring and losing the well. If this possibilityexists, drilling mud is used so that the pressure at depth, dueto the weight of the mud column, will be sufficient to applyforce to the wall of the well supporting the wellbore toprevent collapse.

Pure water has a pressure gradient of 0.433 psi/ft. Imaginedrilling at a depth of 5,000 ft with the wellbore filled with purewater. The pressure at depth on the wall of the well due tothe weight of a static water column would ideally be 2,165.0psig. The absolute pressure would ideally be 2,165.0 psig +atmospheric pressure, or 2,179.7 psia if atmosphericpressure is standard. This means that, on every square inchof the wall of the well, there would be an applied force of2,179.7 lbfacting to support the wellbore.

In order for this force to be effective in permeableformations, it must be greater than the reservoir fluidpressure acting from the reservoir, tending to collapse thewellbore. This condition will exist if the function #4 to bediscussed is met. This pressure at depth due to the weight of

the mud column is supporting the wellbore to preventcollapse.

4. Controlling reservoir fluid pressure to prevent blowout.

Blowout occurs when the Driller loses control of the reservoirfluid pressure. During the drilling operation, the Drillermonitors mud pump speed in spm (strokes/min). For theparticular pumps used, there is a chart that converts thesespm into gpm (gal/min), or a gauge may indicate this mudflow rate directly at the drillers console. The net return mudflow rate is usually monitored by a mud pit level indicator,

which sounds an alarm if the level of drilling muds in thestorage pits exceed a maximum allowed level. The alarmindicates that drilling mud is returning at a higher flow ratethan it is being pumped downhole. The extra flow is enteringthe wellbore from a drilled-into reservoir, which has areservoir fluid pressure higher than the pressure at depthdue to the weight of the drilling mud column.


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If this reservoir fluid entering the well is hydrocarbon withdissolved gas, it will be below the bubble point pressure(BPP) long before it reaches the surface. Therefore, gas willbe released from the hydrocarbon liquids, further reducingthe pressure at depth due to the weight of the fluid column inthe wellbore and increasing the likelihood of a blowout. If thisgas reaches the surface, it is referred to as a gas kick. Thissituation cannot be permitted. The Driller must control it byactivating the blowout prevention system (BOP stack) ifnecessary.

Drilling occurs overbalanced to prevent blowout, meaningthat wellbore pressure is greater than reservoir fluidpressure. If a reservoir should be drilled into with a higherpressure than the wellbore pressure due to the weight of the

mud column, it is necessary to weight up the mud in order tokill the well. This is accomplished by adding solid materialsto the drilling mud liquid base, increasing its density to asufficient level to create the necessary overbalancedcondition and prevent blowout. It may be necessary toactivate the BOP stack in order to provide time for theweighting up procedure. Depending on well depth, thisprocedure may require several hours. If function #4 is beingfulfilled, obviously function #3, to support and stabilize thewellbore to prevent collapse, is also being fulfilled.

5. Sealing the wellbore to minimize fluid loss.

During the drilling operation, drilling is proceedingoverbalanced, with the wellbore pressure greater thanreservoir pressures drilled into. When the hydrocarbonreservoir rock is encountered, it is best that its permeabilitybe as high as possible. Due to overbalanced drilling,however, when the reservoir rock is encountered, there willbe immediate contamination by drilling mud liquids when thatmud flows back into the rock permeability. This drilling mudcontamination of reservoir rock permeability can have majoradverse effects on both well and reservoir productivity,

causing wellbore damage, or skin, measured by the skinfactor.

This contamination must be minimized. Ideally the wellborewould be sealed to prevent fluid loss. However, there willalways be some fluid loss, and contamination of reservoirpermeability before the wellbore seal has been established.


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6. In the case of unexpected loss of mud flow, suspending therock cuttings in the annulus until flow is resumed.

If there is a problem with the mud pump or the power

system, drilling mud flow might be interrupted unexpectedly.Most drilling rigs operate from a central power system.

Assume that drilling occurs in Well #1 at a depth of 8,000 ftwith the 8-3/4" drill bit at a good rate of penetration (ROP)and that this drilling rate has existed for several hours.Suddenly the rig loses power, but the reason for this loss isnot immediately known. All systems shut down. The mudpumps and rotary table stop, and the hoisting system locksthe drillstring, suspending it in the derrick.

If the problem is not identified quickly and drilling resumed, amajor additional problem may develop. When power is lost,cuttings are being transported up the annulus by the drillingmud in 8,000 ft of wellbore. When mud flow stops, thesecuttings will begin to settle back down the annulus aroundthe drill collars at the bottom of the hole. It is likely that thiswill result in sticking the drillstring, which may not berecovered. This possibility must be minimized. The drillingfluid must, in some fashion, suspend the cuttings in theannulus to prevent their fallout until flow is resumed.

7. When drilling with a Bottomhole Drilling Assembly (thePositive Displacement Motor or the Drilling Turbine), the

drilling fluid must transmit the necessary power from thesurface to the bottomhole drilling assembly to rotate the drillbit.

These last five functions require a drilling mud, with the exceptionof function #6, which may be fulfilled with drilling foam.

As shown in Figure 12, the drilling fluid system may be defined asa closed system. When drilling with a gas, a compressor isrequired. When drilling with a liquid, a mud pump is required. Boththe compressor and pump cause the drilling fluid to flow into thestandpipe attached to one leg of the derrick. It then flows through

the rotary hose, swivel, kelly, drill pipe, drill collars, out the jetnozzles of the bit, and up the annulus, where it is exhausted tothe atmosphere at the surface. When drilling with gas, the returnfluid along with the cuttings is exhausted to the atmosphere.When drilling with a mud, it is normally exhausted over the shaleshaker, a vibrating sieve system that removes the larger cuttings.


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From the shale shaker, at predetermined intervals, theroughnecks or the geologist will collect samples of the rockcuttings for geological analysis. After flowing through the shaleshaker, the mud may flow into mud pits or settling tanks and beprepared for recirculation into the wellbore. In some wells, themud system might contain expensive additives to serve variousdownhole functions. The mud is expensive and must bemaintained for recirculation. It may pass through centrifugesystems, desilters, degassers, and other specialized equipment toprepare it for recirculation. In some instances offshore, dependingon the particular situation, the first several thousand feet of a wellmight be drilled using water from the offshore environment.Unless downhole contaminants have been encountered that areunacceptable to the environment, the returning liquid is simplyexhausted back into the offshore environment.

Though most wells require a liquid drilling fluid, Drillers prefer gas,but gas has limited applications: there is the danger of blowout inmost instances, especially with depth. Such situations require thatthe drilling fluid be mud. Air and nitrogen are the preferred gases,and both are considered infinite in the earths atmosphere.Nitrogen is preferable since it does not support combustion andmay be encapsulated in foam. Foam drilling is considered to begas drilling.

When drilling with a liquid base drilling mud, the base is normallywater or oil. Depending on the drilling conditions, it may be freshor salt water. If the liquid base is oil, it is likely an emulsion, withwater present with oil. There are also other liquid bases availablefor drilling muds, such as polymer base mud. Polymers consist oflarge molecules selected to serve the required drilling fluidfunctions for the particular well in which they are being used.Polymer base muds are becoming more common, yet are usuallyexpensive.

The two most common additives in a drilling mud are both solids.One is a colloidal additive. Colloidal is used in this instance toidentify a particle that is so small that it cannot be viewed with an

optical microscope, yet is larger than a molecule. It can be viewedwith an electron microscope. This material is bentonite, a minedclay. Bentonite is an extremely fine powder, as indicated by thecolloidal description, and its particles are flat platelets. Theaddition of bentonite to the drilling mud results in a suspension ofthe solid particles within the liquid base. No chemical reactionoccurs.


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The drilling mud containing bentonite flows through the jet nozzlesof the bit and returns up the annulus. Since drilling is occurringoverbalanced, the mud tends to flow back into the permeability ofpermeable rock formations, contaminating the reservoirpermeability. As this flow begins, the flat platelets of the bentonitewill filter out on the wall of the well and, since platelets are flat,they will quickly overlap and seal the wellbore from further fluidloss. The result is a tough, yet thin wall cake or mud cake fulfillingfunction #5 discussed above. In the laboratory, when this mudcake is created on filter paper to determine its characteristics, it isreferred to as a filter cake.

Bentonite also serves function #6 discussed above. If mud flowshould be interrupted so that the drilling mud column in theannulus becomes stationary, the presence of bentonite in the mud

will cause the mud to gel quickly, thereby suspending the rockcuttings in the annulus and preventing their fallout. In this way,bentonite permits the drilling mud to serve function #6. Drillingwith foam will also fulfill this function.

When the mud pumps are again in operation, the Driller can breakthe gel dynamically. He lifts the drillstring several feet with thehoisting system and starts rotation. The dynamics of the rotationwill break the gel and return the mud to liquid, permitting drilling tocontinue as the rock cuttings are carried back to the surface. Theyhave been prevented from falling out and potentially sticking thedrillstring. Bentonite also assists in fulfilling function #3. Whendrilling overbalanced to prevent blowout, the wellbore pressureencountered. If a permeable rock that is not well consolidated isdrilled into, the higher wellbore pressure will begin to equalize intothe reservoir away from the wellbore. In time, the pressure will beequal across the wall of the well and the wall of the well willcollapse on the drillstring. However, if bentonite is present as inthe drilling mud as an additive, the resultant mud cake will serveas a pressure barrier on the wall of the well, maintaining thedifferential pressure to prevent collapse. Therefore, bentonite isan extremely important additive in the drilling mud.

A second major solid additive is barite. Barite is an abbreviationfor barium sulfate. This is the weighting material used to increasethe density of the mud to control reservoir pressures and preventblowout. Barite is also a suspension within the mud liquid base.


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Pure water has a specific weight of 62.4 lbf/ft3, which converts to

8.34 ppg (lbf/gal). Mud density is usually expressed in ppg,

although some countries and companies express it as specific

gravity or in terms of pressure gradients. Saudi Aramcoexpresses mud density in pcf (lbf / ft3).

If the Driller should encounter an unexpectedly high pressurewhere the density of the drilling mud being used is insufficient tocontrol that reservoir fluid pressure, he adds barite to increase thedensity until the necessary overbalanced condition exists and thewell has been killed. It may be necessary to activate the BOPsystem in order to control the well, to give sufficient time toaccomplish the weighting up of the mud.

There are many other conditions that could occur during drilling.

Assume that the Driller is drilling with a mud flow rate of 300 gpmand finds that the mud pit levels are lowering significantly.Calculations indicate that the mud is returning at a rate of 100gpm. Significant lost circulation exists. The Driller has drilled intoan extremely high permeability rock, a fault, or a cavern, and themud is being lost into the geology. The lost circulation is notnormally this extreme. However, in extreme conditions, it ispossible for the drilling mud in the annulus to flow back downholeinto the geology, removing whatever protection existed againstreservoir fluid pressures in rocks previously drilled through atmore shallow depths. The drilling operation is immediately

exposed to blowout conditions. Drilling cannot be continued untilcirculation has been regained. Even lower rates of lost circulationcannot be permitted, since there may be a considerableinvestment in chemical and other additives in the drilling mud.Lost circulation material (LCM) will be included in the mudpumped into the hole, to attempt to seal across the flow channelspermitting loss of mud. Many variations of materials, includingspecial additives provided by service companies, straw,newspapers, shredded automobile tires, pecan hulls, andcottonseed hulls, may be used for lost circulation. Historically,cottonseed hulls have been a standard lost circulation material.

The most commonly used lost circulation materials can bepumped down the drillstring through the drill bit, but in extremecases it may be necessary to remove the bit.


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The BOP System (Blowout Prevention System)

A blowout occurs when there is a loss of control of downholereservoir fluid pressures. These reservoirs are not necessarily

hydrocarbon reservoirs, but may be other gases or water.Downhole pressures are normally controlled by drillingoverbalanced, so that the wellbore pressure due to the weight ofthe drilling mud column is greater than any reservoir fluidpressures drilled into. Reservoir fluid pressures, however, cannotalways be anticipated. When a higher than expected pressure isdrilled into, it may be necessary to activate the blowout preventionsystem (BOP stack) to provide time to kill the well. The system isreferred to as the BOP stack because it is usually a combinationof, or a stack of, different types of blowout preventers.

When drilling onshore or offshore from a sea floor supportedstructure, the BOP stack is located immediately beneath therotary table. When drilling offshore from a floating vessel, such asa semisubmersible or a drill ship, the BOP stack will be located onthe sea floor. For example, if the offshore operation from thefloating vessel is in 500 ft of water, the BOP stack will be 500 ftdown, on the sea floor.

In the unactivated state, the BOP system does not affect the flowof the drilling fluids. The fluids flow through the drillstring andreturn through the annulus, through the unactivated blowoutpreventers, where they are diverted to exhaust at atmospheric

pressure, either over the shale shaker or into the atmospherewhen drilling with gas. A typical basic BOP stack configuration isshown in Figure 13. It consists of three blowout preventers:

Annular preventer (top)

Blind rams (middle)

Pipe rams (bottom)


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Figure 13. Typical BOP Stack Configuration

The blind rams may also be shear rams. If so, they are referred toas blind/shear rams and provide maximum protection in apotential blowout situation. In the unactivated state, drilling fluidflows through the drill pipe and returns up the annulus through theunactivated preventers.

Annular Preventers -When the Driller activates the annularpreventers, hydraulic fluid applies pressure to a piston surface,forcing a ram wedge upward. A rubber ring is prevented frommoving upward due to a steel restricting shoulder above.Therefore, the ram wedge will force the rubber ring into the

annulus, sealing the wellbore around the drillstring. Many of thesesystems are designed to seal the annulus around any shape inthe wellbore, such as a square or hexagonal kelly. They seal theannulus from downhole pressure, but are considered minimumprotection. They may also be built as stripper preventers. Theirfabrication as stripper preventers implies that equipment,including the drillstring, may be moved from the pressurizedwellbore through the closed preventers.


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Pipe ramsare normally placed on the bottom of the BOP stack.Pipe rams also serve the function of sealing the annulus, but in avery different fashion from the annular preventers. These aremassive pieces of equipment.

When the Driller activates the pipe rams, hydraulic fluid ispumped into opposite chambers, applying pressure to pistons andforcing rams to close around the drill pipe from opposite sides.When closed, the pipe rams have sealed off the annulus. Unlikethe annular preventers, however, these may have the capability ofwithstanding differential pressures as high as 25,000 psi.

When the Driller recognizes that a potential blowout situationexists, indicated by increasing mud pit level, he realizes that theblowout preventers may have to be activated to provide protectionwhile the mud properties are changed to control the downholepressures and kill the well. He normally has several minutes toreact. A typical procedure would be to raise the drillstring with thehoisting system until the first full joint of drill pipe appears abovethe rotary table. With this condition, the swivel, kelly, and one jointof drill pipe would be hanging from the drilling hook in the derrick,above the rotary table. The top externally upset tool joint of thesecond joint of drill pipe in the well would be above the rotarytable. With this ext

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